1. Field of the Invention
The present invention is generally related to the hydrodynamic study of subsoil. In particular, the present invention is related to extraction of hydrocarbons.
2. Description of Related Art
Hydrocarbons are present and move about in porous rock formations called reservoirs. In addition to the fluid that one wants to extract, at least one auxiliary fluid is present in a reservoir of hydrocarbons. The fluid that one wants to extract may be oil or gas, while the auxiliary fluid is generally water. The auxiliary fluid may be naturally found in very small quantities in the rock formations of the reservoir. The term given to this residual water is connate water, but in this case it is immobile. It can also be present in larger quantities in the form of an underground water table, which moves during extraction.
Water may also come from a water injection well and may be used in the oil deposit to drive the hydrocarbons towards a production well. This injected auxiliary fluid maintains or restores the pressure in the deposit. This technique of injecting an auxiliary fluid is often used in the initial stages of oil extraction.
The production of a reservoir depends not only on the static characteristics of the reservoir, such as its dimensions and the type of porous rocks in which the hydrocarbons are found, but also on the dynamic characteristics, as the fluids present move within the reservoir towards the well during extraction. The flow of a first fluid O, in a reservoir containing a second fluid W, is governed, amongst other things, by the effective permeability kefO to the first fluid O. This is obtained from the absolute permeability k of the reservoir saturated in the first fluid O multiplied by a correction factor, which is called the relative permeability krO to the first fluid O in the presence of the second fluid W. This order of magnitude characterises the ease with which the first fluid O, in the presence of the second fluid W, passes through the rock formation in the reservoir.
Nowadays, before taking the decision to work on a new hydrocarbon reservoir, its behaviour is simulated by a computer system using a dynamic model for the flow of the fluids in the reservoir. The dynamic model is constructed in three dimensions with a plurality of simulation units, which are cubes whose average edge size is around ten or so metres. It is important to know as accurately as possible, in particular to carry out the simulation, the variation in the relative permeability krO, krW to at least one of the fluids O, W as a function of the saturation S(W) or S(O) in one of the fluids O or W respectively. The saturation of a rock in one fluid is the fraction of the effective volume of the pores of the rock that is taken up by the respective fluid.
In practice, one of the fluids O in the reservoir is an oil or gas hydrocarbon and the other W is water and it is generally the saturation in water S(W) that is used as a parameter. To construct the dynamic flow model, one needs to know the static characteristics of the reservoir. To do this, one begins by constructing a static model of the reservoir that takes into account the geometric measurements of the reservoir and the geological characteristics of the subsoil. These measurements may be carried out by well logging. The dynamic flow model uses the static model of the reservoir, into which one integrates the basic effective permeability kefO to one of the fluids O, the one which one wishes to extract, in the presence of a residual amount of another fluid W.
In practice, one uses the basic effective permeability to the oil or gas in the presence of residual water. This effective permeability kefO is traditionally obtained by way of a pressure build up test. In this type of test, with the reservoir being traversed by at least one well, one begins to extract the fluid O at a certain flow rate, then the production is stopped and the build up in pressure caused by closing the well is measured. The effective permeability kefO is then deduced from this.
In order to make the dynamic model work, it has to be initialised. To do this, one introduces the flow rate and/or pressure figures expected for the reservoir while it is being worked.
The dynamic model is also initialised with the relative permeability values to each of the fluids as a function of the saturation in one of the fluids. In order for the simulation to be reliable, these relative permeability values must be as accurate as possible. The relative permeability values to each of the fluids may be taken from collections of data concerning the reservoir in question, as this data exists for most of the areas involved in oil and gas prospecting. But in this case, it involves average relative permeability values. In terms of accuracy, it is better to carry out permeability analyses in the laboratory, using well cores taken from the reservoir formation. These well cores are solid cylinders, with a diameter of around 10 centimetres, which are extracted from the subsoil. The saturation measurements are not generally carried out on full well cores but on small samples taken from the well cores. While they are being extracted, these well cores can be subjected to irreversible mechanical stresses, caused by the cutting tool, which can modify their relative permeability. Furthermore, while they are being brought up, they can go through, and become impregnated with, mud, which also changes their relative permeability. In general, the relative permeability values obtained in the laboratory are not then the same as the real relative permeability values, which exist in situ in the reservoir formation.
In addition, the relative permeability values obtained from these small samples must be extrapolated so that they fit the scale of the simulation units, which introduces another source of error. With all this imprecision in the relative permeability values, there is a risk that the dynamic model does not provide a correct representation of the flow of fluids contained within the reservoir at the scale of the simulation units.